Data aggregation for drilling operations

ABSTRACT

A method for aggregating data for a drilling operation. The method includes acquiring the data from a number of data sources associated with the drilling operation, synchronizing a timing of the data for aggregating the data to generate synchronized aggregated data, determining a drilling context based on the synchronized aggregated data, and assigning the determined drilling context to the synchronized aggregated data. The method further includes analyzing the synchronized aggregated data in the drilling context to generate an analysis and presenting the analysis to at least one user.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority, pursuant to 35 U.S.C. §119(e), to thefiling date of U.S. patent application Ser. No. 61/035,310, entitled“System and Method for Performing Oilfield Operations,” filed on Mar.10, 2008, which is hereby incorporated by reference in its entirety.

BACKGROUND

Operations, such as surveying, drilling, wireline testing, completions,production, planning and field analysis, are typically performed tolocate and gather valuable downhole fluids. Surveys are often performedusing acquisition methodologies, such as seismic scanners or surveyorsto generate maps of underground formations. These formations are oftenanalyzed to determine the presence of subterranean assets, such asvaluable fluids or minerals, or to determine if the formations havecharacteristics suitable for storing fluids.

During drilling and production operations, data is typically collectedfor analysis and/or monitoring of the operations. Such data may include,for instance, information regarding subterranean formations, equipment,and historical and/or other data.

Data concerning the subterranean formation is collected using a varietyof sources. Such formation data may be static or dynamic. Static datarelates to, for instance, formation structure and geologicalstratigraphy that define geological structures of the subterraneanformation. Dynamic data relates to, for instance, fluids flowing throughthe geologic structures of the subterranean formation over time. Suchstatic and/or dynamic data may be collected to learn more about theformations and the valuable assets contained therein.

Various equipment may be positioned about the field to monitor fieldparameters, to manipulate the operations and/or to separate and directfluids from the wells. Surface equipment and completion equipment mayalso be used to inject fluids into reservoirs, either for storage or atstrategic points to enhance production of the reservoir.

SUMMARY

A method for aggregating data for a drilling operation. The methodincludes acquiring the data from a number of data sources associatedwith the drilling operation, synchronizing a timing of the data foraggregating the data to generate synchronized aggregated data,determining a drilling context based on the synchronized aggregateddata, and assigning the determined drilling context to the synchronizedaggregated data. The method further includes analyzing the synchronizedaggregated data in the drilling context to generate an analysis andpresenting the analysis to at least one user.

Other aspects of data aggregation for drilling operations will beapparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, described below, illustrate typicalembodiments and are not to be considered limiting of its scope, for dataaggregation for drilling operations may admit to other equally effectiveembodiments. The figures are not necessarily to scale, and certainfeatures and certain views of the figures may be shown exaggerated inscale or in schematic in the interest of clarity and conciseness.

FIGS. 1.1-1.4 depict a schematic view of a field having subterraneanstructures containing reservoirs therein, various operations beingperformed on the field.

FIG. 2 depicts a schematic view, partially in cross-section of adrilling operation of a wellsite.

FIG. 3 depicts a schematic diagram of a system for controlling adrilling operation of a field into which implementations of varioustechniques described herein may be implemented in accordance with one ormore embodiments.

FIG. 4 depicts a schematic diagram of an operation of the wellsiteacquisition and control system of the drilling optimization,collaboration and automated control system of FIG. 3.

FIG. 5 depicts a graph of data synchronization based on signal signaturein accordance with implementations of various techniques describedherein.

FIG. 6 depicts a graph of an example of alarms being triggered bydeviation from a planned profile in accordance with implementations ofvarious techniques described herein.

FIG. 7 depicts a diagram of an actual well trajectory deviating from aplanned well trajectory in accordance with implementations of varioustechniques described herein.

FIGS. 8.1-8.3 depict examples of data displays in accordance withimplementations of various techniques described herein.

FIG. 9 depicts a schematic diagram depicting a collaboration platforminto which implementations of various techniques described herein may beimplemented in accordance with one or more embodiments.

FIG. 10 depicts an example of an application platform that allowsvisualization, optimization, automation, control and collaboration inaccordance with implementations of various techniques described herein.

FIG. 11 depicts a flowchart of a process for controlling a drillingoperation for a field in accordance with implementations of varioustechniques described herein.

FIG. 12 depicts a flowchart of a process for collaboration among aplurality of users for controlling a drilling operation in accordancewith implementations of various techniques described herein.

FIG. 13 depicts an example computer system into which implementations ofvarious techniques described herein may be implemented in accordancewith one or more embodiments.

DETAILED DESCRIPTION

Specific embodiments will now be described in detail with reference tothe accompanying figures. Like elements in the various figures aredenoted by like reference numerals for consistency.

In the following detailed description, numerous specific details are setforth in order to provide a more thorough understanding. In otherinstances, well-known features have not been described in detail toavoid obscuring embodiments of data aggregation for drilling operations.

FIGS. 1.1-1.4 depict simplified, representative, schematic views of afield 100 having a subterranean formation 102 containing a reservoir 104therein and depicting various field operations being performed on thefield 100. FIG. 1.1 depicts a survey operation being performed by asurvey tool, such as seismic truck 106.1, to measure properties of thesubterranean formation. The survey operation is a seismic surveyoperation for producing sound vibrations. In FIG. 1.1, one such soundvibration, a sound vibration 112 generated by a source 110, reflects offhorizons 114 in the earth formation 116. A set of sound vibrations, suchas the sound vibration 112 is received by sensors, such asgeophone-receivers 118, situated on the earth's surface. The datareceived 120 is provided as input data to a computer 122.1 of a seismictruck 106.1, and responsive to the input data, computer 122.1 generatesseismic data output 124. This seismic data output may be stored,transmitted or further processed as desired, for example, by datareduction.

FIG. 1.2 depicts a drilling operation being performed by drilling tools106.2 suspended by a rig 128 and advanced into subterranean formations102 to form a wellbore 136. Mud pit 130 is used to draw drilling mudinto the drilling tools via a flow line 132 for circulating drilling muddown through the drilling tools, then up the wellbore 136 and back tothe surface. The drilling mud is usually filtered and returned to themud pit. A circulating system may be used for storing, controlling, orfiltering the flowing drilling muds. The drilling tools are advancedinto the subterranean formations 102 to reach the reservoir 104. Eachwell may target one or more reservoirs. The drilling tools are adaptedfor measuring downhole properties using logging while drilling tools.The logging while drilling tools may also be adapted for taking coresample 133 as shown, or removed so that a core sample may be taken usinganother tool.

A surface unit 134 is used to communicate with the drilling tools and/oroffsite operations, as well as with other surface or downhole sensors.The surface unit 134 is capable of communicating with the drilling toolsto send commands to the drilling tools, and to receive data therefrom.The surface unit 134 collects data generated during the drillingoperation and produces data output 135 which may be stored ortransmitted. Computer facilities may be positioned at various locationsabout the field 100 (e.g., the surface unit 134) and/or at remotelocations.

Sensors S, such as gauges, may be positioned about the field 100 tocollect data relating to various field operations as describedpreviously. As shown, sensor S is positioned in one or more locations inthe drilling tools and/or at the rig 128 to measure drilling parameters,such as weight on bit, torque on bit, pressures, temperatures, flowrates, compositions, rotary speed, and/or other parameters of the fieldoperation. Sensors S may also be positioned in one or more locations inthe circulating system.

The drilling tools 106.2 may include a bottom hole assembly (BHA) (notshown), generally referenced, near the drill bit (e.g., within severaldrill collar lengths from the drill bit). The bottom hole assemblyincludes capabilities for measuring, processing, and storinginformation, as well as communicating with the surface unit 134. Thebottom hole assembly further includes drill collars for performingvarious other measurement functions.

The bottom hole assembly is provided with a communication subassemblythat communicates with the surface unit 134. The communicationsubassembly is adapted to send signals to and receive signals from thesurface using a communications channel such as mud pulse telemetry,electromagnetic telemetry, or wired drill pipe communications. Thecommunication subassembly may include, for example, a transmitter thatgenerates a signal, such as an acoustic or electromagnetic signal, whichis representative of the measured drilling parameters. It will beappreciated by one of skill in the art that a variety of telemetrysystems may be employed, such as wired drill pipe, electromagnetic orother known telemetry systems.

Typically, the wellbore is drilled according to a drilling plan that isestablished prior to drilling. The drilling plan typically sets forthequipment, pressures, trajectories and/or other parameters that definethe drilling process for the wellsite. The drilling operation may thenbe performed according to the drilling plan. However, as information isgathered, the drilling operation may need to deviate from the drillingplan. Additionally, as drilling or other operations are performed, thesubsurface conditions may change. The earth model may also needadjustment as new information is collected

The data gathered by sensors S may be collected by the surface unit 134and/or other data collection sources for analysis or other processing.The data collected by sensors S may be used alone or in combination withother data. The data may be collected in one or more databases and/ortransmitted on or offsite. The data may be historical data, real timedata, or combinations thereof. The real time data may be used in realtime, or stored for later use. The data may also be combined withhistorical data or other inputs for further analysis. The data may bestored in separate databases, or combined into a single database.

The surface unit 134 may be provided with a transceiver 137 to allowcommunications between the surface unit 134 and various portions of thefield 100 or other locations. The surface unit 134 may also be providedwith or functionally connected to one or more controllers (not shown)for actuating mechanisms at the field 100. The surface unit 134 may thensend command signals to the field 100 in response to data received. Thesurface unit 134 may receive commands via the transceiver 137 or mayitself execute commands to the controller. A processor may be providedto analyze the data (locally or remotely), make the decisions and/oractuate the controller. In this manner, the field 100 may be selectivelyadjusted based on the data collected. This technique may be used tooptimize portions of the field operation, such as controlling drilling,weight on bit, pump rates, or other parameters. These adjustments may bemade automatically based on computer protocol, and/or manually by anoperator. In some cases, well plans may be adjusted to select optimumoperating conditions, or to avoid problems.

FIG. 1.3 depicts a wireline operation being performed by a wireline tool106.3 suspended by a rig 128 and into a wellbore 136 of FIG. 1.2. Thewireline tool 106.3 is adapted for deployment into the wellbore 136 forgenerating well logs, performing downhole tests and/or collectingsamples. The wireline tool 106.3 may be used to provide another methodand apparatus for performing a seismic survey operation. The wirelinetool 106.3 of FIG. 1.3 may, for example, have an explosive, radioactive,electrical, or acoustic energy source 144 that sends and/or receiveselectrical signals to surrounding subterranean formations 102 and fluidstherein.

The wireline tool 106.3 may be operatively connected to, for example,geophones 118 and a computer 122.1 of a seismic truck 106.1 of FIG. 1.1.The wireline tool 106.3 may also provide data to the surface unit 134.The surface unit 134 collects data generated during the wirelineoperation and produces data output 135 that may be stored ortransmitted. The wireline tool 106.3 may be positioned at various depthsin the wellbore 136 to provide a survey or other information relating tothe subterranean formation 102.

Sensors S, such as gauges, may be positioned about the field 100 tocollect data relating to various field operations as describedpreviously. As shown, the sensor S is positioned in wireline tool 106.3to measure downhole parameters which relate to, for example porosity,permeability, fluid composition and/or other parameters of the fieldoperation.

FIG. 1.4 depicts a production operation being performed by a productiontool 106.4 deployed from a production unit or Christmas tree 129 andinto a completed wellbore 136 for drawing fluid from the downholereservoirs into surface facilities 142. The fluid flows from a reservoir104 through perforations in the casing (not shown) and into theproduction tool 106.4 in the wellbore 136 and to surface facilities 142via a gathering network 146.

Sensors S, such as gauges, may be positioned about the field 100 tocollect data relating to various field operations as describedpreviously. As shown, the sensor S may be positioned in the productiontool 106.4 or associated equipment, such as Christmas tree 129,gathering network 146, surface facility 142, and/or the productionfacility, to measure fluid parameters, such as fluid composition, flowrates, pressures, temperatures, and/or other parameters of theproduction operation.

Production may also include injection wells (not shown) for addedrecovery. One or more gathering facilities may be operatively connectedto one or more of the wellsites for selectively collecting downholefluids from the wellsite(s).

While FIGS. 1.2-1.4 depict tools used to measure properties of a field,it will be appreciated that the tools may be used in connection withnon-oilfield operations, such as gas fields, mines, aquifers, storage,or other subterranean facilities. Also, while certain data acquisitiontools are depicted, it will be appreciated that various measurementtools capable of sensing parameters, such as seismic two-way traveltime, density, resistivity, production rate, etc., of the subterraneanformation and/or its geological formations may be used. Various sensorsS may be located at various positions along the wellbore and/or themonitoring tools to collect and/or monitor the desired data. Othersources of data may also be provided from offsite locations.

The field configurations of FIGS. 1.1-1.4 are intended to provide abrief description of an example of a field usable with data aggregationfor drilling operations. Part, or all, of the field 100 may be on land,water, and/or sea. Also, while a single field measured at a singlelocation is depicted, data aggregation for drilling operations may beutilized with any combination of one or more fields, one or moreprocessing facilities and one or more wellsites.

FIG. 2 is a schematic view, partially in cross section of field 200having data acquisition tools 202.1, 202.2, 202.3 and 202.4 positionedat various locations along the field 200 for collecting data of thesubterranean formation 204. Data acquisition tools 202.1-202.4 may bethe same as data acquisition tools 106.1-106.4 of FIGS. 1.1-1.4,respectively, or others not depicted. As shown, data acquisition tools202.1-202.4 generate data plots or measurements 208.1-208.4,respectively. These data plots are depicted along the field 200 todemonstrate the data generated by the various operations.

Data plots 208.1-208.3 are examples of static data plots that may begenerated by data acquisition tools 202.1-202.3, respectively, however,it should be understood that data plots 208.1-208.3 may also be dataplots that are updated in real time. These measurements may be analyzedto better define the properties of the formation(s) and/or determine theaccuracy of the measurements and/or for checking for errors. The plotsof each of the respective measurements may be aligned and scaled forcomparison and verification of the properties.

Static data plot 208.1 is a seismic two-way response over a period oftime. Static plot 208.2 is core sample data measured from a core sampleof the formation 204. The core sample may be used to provide data, suchas a graph of the density, porosity, permeability, or some otherphysical property of the core sample over the length of the core. Testsfor density and viscosity may be performed on the fluids in the core atvarying pressures and temperatures. Static data plot 208.3 is a loggingtrace that typically provides a resistivity or other measurement of theformation at various depths.

A production decline curve or graph 208.4 is a dynamic data plot of thefluid flow rate over time. The production decline curve typicallyprovides the production rate as a function of time. As the fluid flowsthrough the wellbore, measurements are taken of fluid properties, suchas flow rates, pressures, composition, etc.

Other data may also be collected, such as historical data, user inputs,economic information, and/or other measurement data and other parametersof interest. As described below, the static and dynamic measurements maybe analyzed and used to generate models of the subterranean formation todetermine characteristics thereof. Similar measurements may also be usedto measure changes in formation aspects over time.

The subterranean structure 204 has a plurality of geological formations206.1-206.4. As shown, this structure has several formations or layers,including a shale layer 206.1, a carbonate layer 206.2, a shale layer206.3 and a sand layer 206.4. A fault 207 extends through the shalelayer 206.1 and the carbonate layer 206.2. The static data acquisitiontools are adapted to take measurements and detect characteristics of theformations.

While a specific subterranean formation with specific geologicalstructures is depicted, it will be appreciated that the field 200 maycontain a variety of geological structures and/or formations, sometimeshaving extreme complexity. In some locations, typically below the waterline, fluid may occupy pore spaces of the formations. Each of themeasurement devices may be used to measure properties of the formationsand/or its geological features. While each acquisition tool is shown asbeing in specific locations in the field 200, it will be appreciatedthat one or more types of measurement may be taken at one or morelocations across one or more fields or other locations for comparisonand/or analysis.

The data collected from various sources, such as the data acquisitiontools of FIG. 2, may then be processed and/or evaluated. Typically,seismic data displayed in the static data plot 208.1 from the dataacquisition tool 202.1 is used by a geophysicist to determinecharacteristics of the subterranean formations and features. The coredata shown in the static plot 208.2 and/or log data from the well log208.3 are typically used by a geologist to determine variouscharacteristics of the subterranean formation. The production data fromgraph 208.4 is typically used by the reservoir engineer to determinefluid flow reservoir characteristics. The data analyzed by thegeologist, geophysicist and the reservoir engineer may be analyzed usingmodeling techniques.

FIG. 3 is a schematic diagram depicting a system for data aggregationfor a drilling operation of a field. More particularly, FIG. 3schematically illustrates a system for drilling optimization,collaboration and automated control (DOCC). A wellbore 301 is drilled bya drillstring assembly 303 which includes a bottomhole assembly (BHA)308 and a drillstring 307. A wellsite acquisition and control system 302collects surface data from a drilling rig 311 and downhole data from theBHA 308. Other drilling related surface and/or downhole data may becollected through other data aggregators, such as a third partyaggregator 304, and passed to the wellsite acquisition and controlsystem 302.

The wellsite acquisition and control system 302 directly interacts witha surface component (not shown) at the drilling rig 311 (e.g, surfaceunit, the rig, pump, mud system, telemetry system, etc.) to acquire realtime data and to control the operation of various drilling systemcomponents. The wellsite acquisition and control system 302 may alsodirectly interact with an acquisition, control and telemetry system 306at the drilling BHA 308. The surface component may provide direct dataacquired from surface measurement sensors. Alternatively, it may alsoinclude data acquired from other acquisition systems such as the thirdparty aggregator 304.

Real-time data may be acquired by the centralized data and collaborationserver 310, 320 from multiple data sources (e.g., 332, 334, 336). Thoseskilled in the art will appreciate that real-time data may be obtainedfrom any number of data sources. At the beginning of a data aggregationoperation, clocks (e.g., 342, 344, 346) at each data source aresynchronized with a clock 319 at data server 310/collaboration server320. All acquired data is time-stamped at the source and transmitted tothe data and collaboration server 310, 320. For data sources that cannotprovide a timestamp, a token, schematically designated by referencenumber 322, may be passed between the data source and the dataserver/collaboration server 310, 320 to determine the round-triplatency. At the data server 310 and collaboration server 320, real-timedata coming in from various data sources is properly adjusted to ensurethat they refer to the same time clock. Those skilled in the art willappreciate that the drilling system 311, wellsite acquisition andcontrol system 302, the third party aggregator 304, and/or the bottomhole assembly 308 may correspond to data sources as described above.

The wellsite acquisition and control system 302 transmits the data itcollects to the centralized data and collaboration server 310, 320 whichmay be located locally or remotely using wired or wireless technology.One or more real time optimization, control and collaborationapplication(s) (hereafter RTOCC application(s)) 312 may be used tomonitor and analyze the drilling operation. Specifically, the RTOCCapplication(s) 312 may provide a plurality of users with access to thesame drilling data from the wellsite acquisition and control system 302for participating in job monitoring, optimization, automation andcollaboration of the drilling operation as will be described more fullyhereinafter.

The RTOCC application(s) 312 may be located in proximity to each other.Alternatively, the RTOCC application(s) 312 may be located remotely fromeach other. One of a plurality of RTOCC applications(s) 312 may beenabled to send a control command to affect a drilling operation. Asatellite (now shown) may be used to enable data/voice/videocommunication between the wellsite acquisition and control system 302and remotely located users and among users that may be remotely locatedwith respect to one another.

The wellsite acquisition and control system 302 is illustrated ingreater detail in FIG. 4. More particularly, FIG. 4 is a schematicdiagram depicting operation of the wellsite acquisition and controlsystem of the drilling optimization, collaboration and automated controlsystem of FIG. 3. The wellsite acquisition and control system 302generally includes various acquisition and control system hardware andsoftware.

As shown in FIG. 4, the wellsite acquisition and control system 302receives input data from the wellsite as shown at 402, and outputs datato the wellsite as shown at 404. In addition, the wellsite acquisitionand control system 302 transmits/receives data to/from other analysis orcontrol applications as shown at 406, and transmits/receives datato/from data repository/server 310/320 illustrated in FIG. 3 as shown at408.

The wellsite acquisition and control system 302 is configured toaggregate and synchronize data from various different acquisitioncomponents. A description of the process of aggregation andsynchronization follows and may be implemented as block 1108 in theflowchart of FIG. 11.

The wellsite acquisition and control system 302 includes a synchronizingmechanism for synchronizing clocks among various different acquisitioncomponents 410, for example, sensors S illustrated in FIGS. 1.2-1.4, atthe wellsite. At this stage, the wellsite acquisition and control system302 acquires data from the various acquisition components (i.e., datasources) as shown at 412. Acquired data may include both surface data(e.g., tripping speed, hookload) and downhole data (e.g. survey data,measurements).

The time that each item of data was created and sent from a data sourceis identified 414. The time may be identified by time-stamping each itemof data at the data source and transmitting the time stamp to the serverwith the item of data. Alternatively, for data sources that cannotprovide time stamps, a token is passed between the data source and theserver to permit the round-trip latency of the item of data to bedetermined. In this case, the time the data item was created isidentified based on the time of receipt at the server as adjusted by theround-trip latency. Models may also be used, for instance, to estimatethe transmission time of a measurement while drilling tool from downholeto surface (based on the sound wave propagation in drilling mud).

At the server, the data acquired from the plurality of sources is timeadjusted to refer to the same clock 416. Once the data is placed on thesame clock, as will be described more fully hereinafter, the wellsiteacquisition and control system 302 then aggregates, aligns and bins theacquired data for efficient analysis as shown at 418. At this stage, thewellsite acquisition and control system 302 may also determine adrilling context, such as the drilling, tripping, etc., and key eventsas shown at 420.

The drilling context is also referred to herein as “Rig State.” The RigState computation may automatically compute the state of the rig basedon surface (and/or downhole) sensors by determining the separateprobabilities of the rig being, for example, in slips, on bottomdrilling, pumping, rotating the drillstring, and moving the drillstringaxially. These probabilities may be combined to determine whether therig is in one of any number of possible states. Those skilled in the artwill appreciate that the number of states may be determined based on thegranularity of information required. The current Rig State may provide acontext for other data that is being interpreted or analyzed.

The wellsite acquisition and control system 302 also includesacquisition and control software, including an application that providesa human interface for the wellsite operation to interact with theacquisition and control system. The acquisition and control software mayalso provide additional intelligence to interpret acquisition data (suchas de-modulating mud pulse signal, etc). Furthermore, a basic automatedcontrol algorithm can be built into the software to ensure the operationis fail-safe. For example, if a particular parameter is about to exceeda critical value, the automated control feature may notify the controlsystem to either shutdown the operation, or perform certainmanipulations (such as to reduce the pump pressure) to maintain thesystem in safe mode.

Referring back to FIG. 3 and the data flow schematically depictedtherein, as indicated above, the wellsite acquisition and control system302 also interacts with the acquisition, control and telemetry system306 at the drilling BHA 308. The acquisition, control and telemetrysystem 306 acquires key downhole data, and uses a telemetry system totransmit the data to the surface. The acquisition, control and telemetrysystem 306 may also have computing power to process acquired data, andfeedback the processed results to the downhole control system. Thedownhole control system controls the movements of the BHA 308, e.g.,orientation, which in turn causes a change to well trajectory.

Communication between the surface wellsite acquisition and controlsystem 302 and the downhole acquisition, control and telemetry system306 may be one-way only, where the data may flow only from downhole tothe surface. In some embodiments, however, the communication between thesurface wellsite acquisition and control system 302 and the downholeacquisition, control and telemetry system 306 is two-way, where the datamay be sent from surface to downhole, and vice versa. With two-waycommunication, the operation of the BHA 308 may be controlled either bythe wellsite acquisition and control system 302 or by any of real-timemonitoring, optimization, collaboration and control applications (RTOCCapplications) 312.

FIG. 3 also illustrates a data server 310/collaboration server 320. Thedata server 310 serves as an acquisition data repository. It interactswith the wellsite acquisition and control system 302 to receive thereal-time data, and provides the mechanism for data retrieval by otherapplications (such as a drilling optimization, collaboration and controlapplication). The data server 310 also interacts with other applications(such as the RTOCC application(s) 312) to receive key optimization data.Any data stored in the data server 310 is available to any applicationsconnected to the server. As a result, wellsite acquisition and controlsystem 302 may receive RTOCC data through an interface at data server310. An example of data server 310 may be based on the OPC (OLE forProcess Control) server concept (“OLE” stands for “Object Linking andEmbedding”). The data server 310 may reside at the wellsite, or at alocation remote from the wellsite. Alternatively, the data/collaborationserver (310, 320) may be implemented as multiple data/collaborationservers, where one of the servers is located at the wellsite and theother server is located at a location remote from the wellsite. In thiscase, the data/collaboration server (310, 320) may be configured toperiodically synchronize data to ensure that users at both locations(i.e., the wellsite and the remote location) are accessing the sameinformation

The collaboration server 320 may be provided if real-time collaborationis needed or desired. The collaboration server 320 allows users who usethe RTOCC applications 312 to share their analysis information. Forexample, real-time voice, data, and whiteboard communications may beenabled through the collaboration server 320.

The data server 310 has access to all operation parameters, allowingmany features to be integrated into the server. Such features may, forexample, include:

-   -   Automated control features: the data server 310 may analyze all        parameters (both acquisition data and key analysis data) and        determine whether certain operation parameters require        modification. If modifications are required, the data server 310        may send out a control command to the wellsite acquisition and        control system 302 to initiate the modifications.    -   Alarm callouts: when the data server 310 receives an alarm from        the wellsite acquisition and control system 302, or from an        RTOCC application 312, the data server 310 can work in        conjunction with the collaboration server 320 to notify the        appropriate individuals at the appropriate time. Since the        collaboration server 320 provides real time voice and data        communication, the collaboration server 320 may configure the        notification list based on the level of alarms and send out the        notification in a manner that is most suitable to the users.

In FIG. 3, the RTOCC applications(s) 312 provide two majorfunctionalities. Initially, by using the real-time data from the dataserver 310, the RTOCC applications 312 may monitor and analyze drillingperformance in real-time. In this case, the drilling context may bedetermined at the RTOCC application 312, instead of at the wellsiteacquisition and control system 302. In addition, by analyzing previousdrilling data (historical data) from offset wells (either coming fromthe data server, or from a separate source), the RTOCC application(s)312 provide relevant information to anticipate potential drillingproblems proactively. With the availability of both real-time andhistorical data, an optimized drilling program can be developed, whichmaybe used to initiate control of a drilling operation. The controlcommand can be issued from RTOCC application(s) 312 and transmitted tothe data server 310, which, in turn, transmits the command to thewellsite acquisition and control system 302. Alternatively, the controlcommand can be directly issued from an RTOCC application 312 anddelivered to the wellsite acquisition and control system 302.

The RTOCC application(s) 312 may also include collaboration features toenable users from different locations (either across a rig floor, oracross a wide geographical area) to share information. The system ofFIG. 3 may include any number of RTOCC applications 312 being runsimultaneously, and which may communicate with each other through thedata and/or collaboration servers 310, 320.

The collaboration features may include, for example, voice, data andwhiteboard collaboration. Such collaboration features allow users atdifferent locations to monitor the progress of an ongoing jobsimultaneously and to participate in real-time discussions to diagnoseand identify possible solutions to any potential drilling problems.

In a collaboration environment, one RTOCC application 312 may bedesignated as a master RTOCC application such that control commands forwellsite acquisition and control system 302 may be issued only throughthis master RTOCC application. Different RTOCC application(s) 312 mayserve as the master DOCC at different times, but only one RTOCCapplication 312 can serve as the master RTOCC application at any giventime. Alternatively, there may not be a master RTOCC applicationdesignated, in which case, each RTOCC application 312 may issue controlcommands to the wellsite acquisition and control system 302. In thisalternative embodiment, additional control features may be built withinthe wellsite acquisition and control system 302 to avoid any conflict inexecuting the control commands from various RTOCC application(s) 312.

Operation data may be acquired in various ways. Downhole data, forexample, may be acquired through downhole mechanical and electricsensors on the BHA 308. The downhole data is sent to wellsiteacquisition and control system 302 by various telemetry mechanisms,e.g., wired telemetry or wireless telemetry (for example, using pressurepulse technology). Acquired data may be time-stamped at the moment thedata is acquired downhole. Alternatively, acquired data may betime-stamped at data server 310/collaboration server 320 taking intoaccount the time lag for the data to arrive from downhole.

Surface data may also be obtained in various ways from one or aplurality of data sources. For example, surface data may include dataacquired from a service company that collected the data, or be datacollected by a client or by one or more third parties (i.e., third partyaggregators 304).

Once operation data is acquired in real-time, the operation data may becombined with planned data and/or relevant data from multiple sourcesfor data analysis, identify potential issues in the operation. Theplanned data may include, but is not limited to, a planned welltrajectory, tubulars, and a drilling program. Alternatively, data fromrepresentative offset wells may be used to predict operationalparameters for the planned well. An optimized plan may specifytolerances for all operational parameters. If the operation parametersdeviate from one or more specified tolerances, an intervention or areplan may be triggered. Hazards, constraints, limits and tolerances aredefined during planning phases to be used for data analysis. Such dataanalysis is typically done at an RTOCC application 312.

In some embodiments, acquired data may be properly time-stamped at itssource at the moment it is acquired. In the event that the data is nottime-stamped at its source, the data may be time-stamped along the datatransmission path, for example, at the moment the data reaches thewellsite acquisition and control system 302 or at the moment it arrivesat the data server 310/collaboration server 320. With each data pointproperly time-stamped at the data server 310/collaboration server 320,the acquired data may be synchronized for monitoring and analysis. Notethat data collection and synchronization may be done at the wellsiteacquisition and control system 302, the data server 310, and/or thecollaboration server 320.

Those skilled in the art will appreciate that data channels may alsosynchronized relatively based on a correlated signature of data.

Synchronization based on a correlated signature of data is discussedbelow in more detail with respect to FIG. 5.

While specific components are depicted and/or described for use in theunits and/or modules of the drilling optimization, collaboration andautomated control, it will be appreciated that a variety of componentswith various functions may be used to provide the formatting,processing, utility and coordination functions necessary to provide dataaggregation for drilling operations in the drilling optimization,collaboration and automated control. The components may have combinedfunctionalities and may be implemented as software, hardware, firmware,or combinations thereof.

FIG. 5 illustrates a graph of data synchronization based on a signalsignature. Suppose a first data channel 502 has a signature 508, whichis correlated to the signature 510 of a second data channel 504 (i.e.,the signatures occur simultaneously). By plotting the data channelstogether on the same time-based log, as shown in FIG. 5, it can be seenthat the clock on channel 502 and the clock on channel 504 are off by 40minutes as shown at 506. By adjusting the time index of these twochannels accordingly, the data channels can be synchronized on the sameclock.

Once all acquired data is properly placed on the same clock using thesynchronization methods discussed with respect to FIGS. 4 and 5, thedata may be further processed to properly align the data for efficientdata analysis. This alignment processing is called data “binning”, ordata re-sampling. The binning size may be fixed, i.e., the intervalbetween any two adjacent data points is constant for all data points.Alternatively, the binning size may be variable, i.e., the intervalbetween any two adjacent data points is not a constant. For greaterefficiency, the data bin size, or the re-sampling frequency, isdetermined by the application that consumes that data. A number ofschemes are available to perform data binning, including, but notlimited to, the following schemes:

Scheme 1: Binning Based on the Highest Frequency Data

A minimal data bin size is determined based on the highest frequency ofthe data channel that is received (i.e., highest data rate). Any datachannel that has lower frequency is processed into this highestfrequency. Certain binning rules should be applied consistently on alldata channels to maintain consistency. A diagram that illustrates aprocess of binning data channels based on highest frequency is shown inTABLE 1.

TABLE 1 Channel A Time 0 2 4 6 8 10 12 Value A1 A2 A3 A4 A5 A6 A7Channel B Time 0 5 10 15 20 25 30 Value B1 B2 B3 B4 B5 B6 B7 Channel B(after processed, based on the frequency of channel A) Time 0 2 4 6 8 1012 Value B1 B1 B1 B2 B2 B2 B3

Scheme 2: Binning Based on the Optimized Binning Size Determined by theApplication that Consumes the Data

The application that consumes the data determines a fixed binning size.All channel data is processed to fit this determined binning size.Again, certain binning rules may be applied to achieve consistency. Adiagram that illustrates a process of binning based on a bin size of 3is shown in TABLE 2.

TABLE 2 Channel A Time 0 2 4 6 8 10 12 Value A1 A2 A3 A4 A5 A6 A7Channel B Time 0 5 10 15 20 25 30 Value B1 B2 B3 B4 B5 B6 B7 Time 0 3 69 12 15 18 Channel A (after processed) Value A1 0.5 A4 0.5 A7 0.5 *(A8 + A9) A10 (A2 + A3) (A5 + A6) Channel B (after processed) Value B1B1 B2 B2 B3 B4 B5

Scheme 3: Variable Binning Size

In this scheme, the time index for processed data channels is simply acombination of all available data channels. A diagram that illustrates aprocess of binning based on a variable binning size determined by thetime interval between any two acquired data points is shown in TABLE 3.

TABLE 3 Channel A Time 0 2 4 6 8 10 12 Value A1 A2 A3 A4 A5 A6 A7Channel B Time 0 5 10 15 20 25 30 Value B1 B2 B3 B4 B5 B6 B7 Time 0 2 45 6 8 10 Channel A (after processed) Value A1 A2 A3 0.5 (A3 + A4) A4 A5A6 Channel B (after processed) Value B1 B1 B1 B2 B2 B2 B3

The results of data analysis may be used in the many ways to aid indrilling operations. Examples of different ways analysis results may beused include, but is not limited to:

-   -   For monitoring and display    -   To identify drilling problems, and/or to trigger alarms    -   For drilling optimization    -   For automation and control    -   For economic analysis of the drilling operation

FIG. 6 is a graph that schematically illustrates an example of alarmsbeing triggered by deviation from a planned profile. In the exampleillustrated in FIG. 6, alarms are triggered by an abrupt change in anactual parameter 602 at point 604, and by the deviation of a plannedprofile 606 exceeding a prescribed tolerance 608 at point 610. Variouskinds of alarms can be raised in this manner. For example, alarms can betriggered when operation conditions exceed safe operation limits of thedrilling equipment. Alternatively, alarms can also be raised whenoperation procedures deviate from a prescribed procedure. Yet further,alarms can be raised when a well trajectory deviates from a planned welltrajectory by more than an allowed tolerance. Alarms can be in the formof visual alarms, audio alarms or both visual and audio alarms.

FIG. 7 depicts a diagram of an actual well trajectory 702 deviating froma planned well trajectory 708. In FIG. 7, the actual well trajectory 702from a rig 704 to a target location 706 deviates from planned welltrajectory 708 as shown at 710. By using a feedback control loop, forexample, the actual well trajectory 702 can be corrected in real-time toreach the target 706 location.

Many simple alarms can be directly built on the data channels discussedwith respect to FIGS. 4 and 6. These simple alarms evaluate the acquireddata against a simple threshold, such as

-   -   If a value of channel A>threshold 1    -   If values of channel A>threshold 1 AND a value of channel        B<threshold 2

Using data analysis, more advanced alarms (“smart alarms”) may be builtinto the RTOCC application to improve operation safety and efficiency.These “smart alarms” require advanced data analysis (e.g., to determinea signal pattern) before a logic condition is applied. For example,smart alarms may be used in, but not limited to, the followingscenarios:

-   -   To detect a signature in data    -   To compare data to reference data    -   To eliminate exceptions/false alarms    -   Simple alarm states combined to yield higher level alarm    -   Used in combination with action/intervention    -   Results fed into a control loop

Smart alarms may be designed based on a deterministic model.

However, a probabilistic approach for designing the smart alarms may beused, for example:

-   -   Compatibility with safety, efficiency and financial decisions        -   Risks—probability of an event        -   Finance—probability of exceeding budget    -   Utilization of all available/pertinent information        -   Low accuracy measurements        -   Multiple sources for same measurement    -   Probabilistic outputs may be combined to yield a higher level        alarm

Data analysis allows users to have a quantitative view of an entiredrilling operation with regard to service quality, safety and drillingefficiency, which, in turn, can be used to obtain an economic benefit.For example, if one service company is able to demonstrate througheffective data analysis that it has less service quality issues and/orbetter drilling efficiency, it is likely that a client may share thebenefit of increased efficiency or safety with the service company. Orsimply, the service company may have an edge in obtaining the nextservice contract from the client.

With the availability of modern data acquisition systems, currentdrilling operations generate an enormous quantity of data over a timespan from weeks to months. An RTOCC application may be configured topresent this data to drilling engineers in the most effective manner toallow quick identification of drilling problems and/or of the situationdownhole. For example, displaying complicated data in differenttime-related synchronized views such as the following facilitates humanunderstanding of the data:

-   -   Display historical, real-time and modeled data in correlation        with time.    -   Display data in an unlimited numbers of different views and        formats.    -   Focus all displays and views on a specific time point or period        without requiring manual reconfiguration of the displays.    -   Display data filtered by a time breakdown of rig operations        (i.e., data displayed within the context of rig operations).

Data display and monitoring is typically done at an RTOCC application.FIGS. 8.1-8.3 illustrate examples of data displays. In particular, FIG.8.1 illustrates a display of 2-dimensional graphics applied to real-timeand/or historical time and depth data. In this example, multiplecontexts for depth context data 802, 804 are provided. The first depthcontext data 802 is shown in terms of the drill string, where thebottom-hole assembly is synchronized to time and drawn to scale 806. Thesecond depth context data 804 is shown in terms of the rig operationstate 808 along with a time line showing the current time 810.

FIG. 8.2 illustrates displays of data presented in different formats,where all displays are synchronized to a time line and controlled by atime line synchronization control (not shown). In this example, thetime-synchronized data is simultaneously displayed in a log format 812,a numerical format 814, and in a cross plot (i.e., in a time and depthcontext) 816. In some embodiments, each of the different formats may beupdated appropriately as the data is received in real-time.

FIG. 8.3 illustrates a display showing trajectory data in a controlledrange associated by a time. In this example, the trajectory data isdisplayed in terms of both a vertical section (i.e., depth versusazimuth) 818 and a horizontal section 820 (i.e., north versus east). Thedisplay also includes trajectory parameters 822 for the current positionof a drilling operation.

In some embodiments, the data analysis, data display and monitoringdescribed above is for achieving optimization of a drilling operation inorder to make the drilling process more efficient and effective.Optimizations may involve completing a drilling operation with minimalcost or risk, or maximizing the drilling rate within a particular stageof a drilling operation. Although the output of an optimization is oftenrelatively easy to measure, most drilling optimizations requireunderstanding many measurements in the proper context and controllingmultiple driving parameters. It is also the nature of drilling thatoptimizations are localized as such optimizations are a continuousprocess.

The DOCC system enables optimization to be achieved in various manners,including, but not limited to, the following:

-   -   Providing a method to view planned and actual data by displaying        the difference between the data in correlation to a time period    -   Providing a mechanism allowing users to easily setup or modify        conditional alarms, or configure the synchronized display    -   Displaying all operation parameters within the context of rig        operations    -   Obtaining and synchronizing high resolution real-time data    -   Automatically determining the context of current rig operations    -   Real-time computation of drilling models    -   Graphical analyses measurement tools in the context of a        drilling operation    -   Collaboration of tools to enable expertise from different        engineering disciplines    -   Computation of new settings of drilling driving parameters.

In some embodiments, the data analysis, data display and monitoring, andoptimization provides feedback for a drilling engineer to modifyoperation parameters in order to achieve operation objectives (e.g.,following a planned trajectory, avoiding/reducing operation failures,and/or increasing operation efficiency). The drilling engineer may usefeedback information to manually alter operation parameters (e.g.,increasing of decreasing the drilling speed, increasing or decreasingpump pressure (pump flow rate), changing the toolface, etc).Alternatively, the feedback information may be used to automaticallyalter the operation parameters without requiring user intervention.

Automation is an important mechanism for improving drilling operations.Automation allows for finer control over a drilling process and maydeliver a consistency that users are not typically capable of providing.Automation may enable remote drilling by taking less frequent and laggedcommands/set points and executing them at the wellsite. In the DOCCsystem of FIG. 3, automation makes use of the drilling context, alarmsand operating status made available by data analysis, data display andmonitoring, and optimization to better control the drilling operations.Examples of automation processes may include, but is not limited to:

-   -   A modelling of the system being automated    -   Measurement of variables required for automation at the        appropriate frequency to accomplish the automation    -   Monitoring context information and alarm conditions to enable,        adjust or suspend automation    -   Measuring and controlling driving parameters for the process        being automated    -   Measuring an output condition and utilizing the model to        determine adjustments needed

FIG. 9 is a schematic diagram depicting a collaboration platform. One ora number of users 902, 904, 906, 908 may be using RTOCC applications912, 914, 916, 918, respectively, at geographically disparate locationsand collaborate with one another via a data server 310/collaborationserver 320. An RTOCC application may provide one or more of thefollowing functions for collaboration:

-   -   Drilling data visualization and analysis    -   Data communication with another instance of the RTOCC        application    -   Voice communication with another instance of the RTOCC        application    -   Video communication with another instance of the RTOCC        application    -   Image, file and annotation sharing with another instance of the        RTOCC application

One instance of an RTOCC application may communicate with anotherinstance of an RTOCC application. Alternatively, all the instances ofthe RTOCC applications may communicate with each other in a “conference”type mode.

The data server 310/collaboration server 320 system also enablesmultiple users of the RTOCC applications to collaborate with respect toa drilling operation. The users may be physically located in the sameoffice, or the users may be physically separated from one another byhundreds or even thousands of miles. The collaboration allows multipleusers to:

-   -   View the same drilling operation data, in the same manner (if        using the same configuration) or in the manner each user prefers    -   Share discussions of the drilling operation through instant        messaging, voice communication, video communication, and real        time chat    -   Share a drawing whiteboard    -   Share any annotations or events for the drilling operation        generated by a RTOCC application or by any users    -   Receive notifications of alarms or events related to the        drilling operation by subscription. Notifications may be in the        form of an electronic message, a pager, a text message, a mobile        phone call, etc.

Alarm subscriptions are a powerful tool for drilling collaboration.

Since a drilling operation involves many different services andtechnologies, collaborating users may be interested in only one or a fewservices or technologies. By using an alarm or event subscriptionservice, a collaborating user may choose to receive notifications ofonly the events that the user is most interested in.

FIG. 10 illustrates an example of an application platform that allowsvisualization, optimization, automation, control and collaboration. Theapplication platform allows creation of multiple canvases (“views”)based on the needs of a particular job. In this example, the displayshows an overview of all necessary drilling data (e.g., data explorerand view controller 1002, alarms and optimization control 1004, dataanalog gauge 1006, time data analysis plot 1008, synchronized time anddepth log 1010, computations control 1012, component input and propertycontrol 1014, depth data analysis plot 1016, well activities control1018, numeric gauge 1020, rig operations and pie charts 1022, trajectoryanalysis vs. plan 1024, etc.).

In other embodiments, a number of views (e.g., “washout monitoring”,“backoff/twistoff monitoring”, “stuck pipe detection”) may be configuredby users based on their specific activity requirements. In this case,the views may be displayed simultaneously on one or a number of screensfor a situational display of a drilling operation. Each view may includeany number of components including but not limited to the componentsshown in FIG. 10.

FIG. 11 is a flowchart of a process for controlling a drilling operationfor a field. It should be understood that the operations illustrated inthe flow diagram are not limited to being performed by the process.Additionally, it should be understood that while the operational flowdiagram indicates a particular order of execution of the process, insome implementations, certain portions of the process might be executedin a different order.

The process is generally designated by reference number 1100, and beginsby monitoring a drilling operation (block 1102). Data is acquired from aplurality of data sources with respect to the drilling operation (block1104). The data may be real-time data. Other data, including historicaldata and planning data may also be acquired from one or more datasources (block 1106). The acquired data from the data sources and anyother acquired data is aggregated to generate aggregated data (block1108). The aggregating may include synchronizing a timing of theacquired data to form synchronized aggregated data as discussed abovewith respect to FIG. 4. A drilling context is then determined from theaggregated data (block 1110), and the aggregated data is assigned thedrilling context (block 1112). The drilling context may be assigned asdiscussed above with respect to FIG. 4. The aggregated data is analyzedin the assigned drilling context to form an analysis (block 1114). Theanalysis is presented to a plurality of users (block 1116), and thedrilling operation is adjusted in accordance with the analysis and inputof each of the plurality of users (block 1118). After a control commandis issued, the response to the control command may be verified (block1120). This may be done by acquiring and analyzing real-time data. Forexample, if a command is issued to increase the weight on the drill bitto 10 kilo pounds, real-time data is used to confirm that the weight is,in fact, increased to 30 km. If the data indicates otherwise, atroubleshooting operation may be required.

FIG. 12 is a flowchart of a process for collaboration among a pluralityof users for controlling a drilling operation. It should be understoodthat the operations illustrated in the flow diagram are not limited tobeing performed by the process. Additionally, it should be understoodthat while the operational flow diagram indicates a particular order ofexecution of the process, in some implementations, certain portions ofthe process might be executed in a different order.

The process is generally designated by reference number 1200, and may beimplemented by blocks 1114 and 1116 in FIG. 11. The process begins byproviding aggregated acquired data to each of a plurality of real-timemonitoring, optimization, collaboration and control applications (block1202). Each application monitors and analyzes the aggregated acquireddata in the drilling context in real-time to form an analysis (block1204). Each application additionally presents the analysis to one ormore users (block 1206). The presentations may include graphical andother displays in one or more views and/or formats.

The users may collaborate with one another to discuss the results of theanalysis, to identify potential problems with the drilling operation,and to identify possible solutions to any identified problems (block1208). The collaboration may occur as discussed above with respect toFIG. 9. Based on the collaboration, decisions may be made regarding thedrilling operation (e.g., adjustments to the drilling operation, ceasingdrilling operations, etc.) (block 1210).

Embodiments of data aggregation for drilling operations (or portionsthereof), may be implemented on virtually any type of computerregardless of the platform being used. For example, as shown in FIG. 13,a computer system 1300 includes one or more processor(s) 1302,associated memory 1304 (e.g., random access memory (RAM), cache memory,flash memory, etc.), a storage device 1306 (e.g., a hard disk, anoptical drive such as a compact disk drive or digital video disk (DVD)drive, a flash memory stick, etc.), and numerous other elements andfunctionalities typical of today's computers (not shown). The computersystem 1300 may also include input means, such as a keyboard 1308, amouse 1310, or a microphone (not shown). Further, the computer system1300 may include output means, such as a monitor 1312 (e.g., a liquidcrystal display (LCD), a plasma display, or cathode ray tube (CRT)monitor). The computer system 1300 may be connected to a network (notshown) (e.g., a local area network (LAN), a wide area network (WAN) suchas the Internet, or any other similar type of network) with wired and/orwireless segments via a network interface connection (not shown). Thoseskilled in the art will appreciate that many different types of computersystems exist, and the aforementioned input and output means may takeother forms. Generally speaking, the computer system 1300 includes atleast the minimal processing, input, and/or output means necessary topractice one or more embodiments.

Further, those skilled in the art will appreciate that one or moreelements of the aforementioned computer system 1300 may be located at aremote location and connected to the other elements over a network.Further, one or more embodiments may be implemented on a distributedsystem having a plurality of nodes, where each portion may be located ona different node within the distributed system. In one or moreembodiments, the node corresponds to a computer system. Alternatively,the node may correspond to a processor with associated physical memory.The node may alternatively correspond to a processor with shared memoryand/or resources. Further, software instructions for performing one ormore embodiments of data aggregation for drilling operations may bestored on a computer readable medium such as a compact disc (CD), adiskette, a tape, or any other computer readable storage device.

The systems and methods provided relate to the acquisition ofhydrocarbons from a field. It will be appreciated that the same systemsand methods may be used for performing subsurface operations, such asmining, water retrieval and acquisition of other underground materials.Further, portions of the systems and methods may be implemented assoftware, hardware, firmware, or combinations thereof.

While specific configurations of systems for performing data aggregationfor drilling operations are depicted, it will be appreciated thatvarious combinations of the described systems may be provided. Forexample, various combinations of selected modules may be connected usingthe connections previously described. One or more modeling systems maybe combined across one or more fields to provide tailored configurationsfor modeling a given field or portions thereof. Such combinations ofmodeling may be connected for interaction therebetween. Throughout theprocess, it may be desirable to consider other factors, such as economicviability, uncertainty, risk analysis and other factors. It is,therefore, possible to impose constraints on the process. Modules may beselected and/or models generated according to such factors. The processmay be connected to other model, simulation and/or database operationsto provide alternative inputs.

It will be understood from the foregoing description that variousmodifications and changes may be made in embodiments of data aggregationfor drilling operations without departing from its true spirit. Forexample, during a real-time drilling of a well it may be desirable toupdate the field model dynamically to reflect new data, such as measuredsurface penetration depths and lithological information from thereal-time well logging measurements. The field model may be updated inreal-time to predict key parameters (for example, pressure, reservoirfluid or geological composition, etc.) in front of the drilling bit.Observed differences between predictions provided by the original fieldmodel concerning well penetration points for the formation layers may beincorporated into the predictive model to reduce the chance of modelpredictability inaccuracies in the next portion of the drilling process.In some cases, it may be desirable to provide faster model iterationupdates to provide faster updates to the model and reduce the chance ofencountering any expensive field hazard.

The flowcharts and block diagrams in the different depicted embodimentsillustrate the architecture, functionality, and operation of somepossible implementations of methods, apparatus, and computer programproducts. In this regard, each block in the flowchart or block diagramsmay represent a module, segment, or portion of code, which comprises oneor more executable instructions for implementing the specified functionor functions. In some alternative implementations, the function orfunctions noted in the block may occur out of the order noted in thefigures. For example, in some cases, two blocks shown in succession maybe executed substantially concurrently, or the blocks may sometimes beexecuted in the reverse order, depending upon the functionalityinvolved.

This description is intended for purposes of illustration only andshould not be construed in a limiting sense. The scope of dataaggregation for drilling operations should be determined only by thelanguage of the claims that follow. The term “comprising” within theclaims is intended to mean “including at least” such that the recitedlisting of elements in a claim are an open group. “A,” “an” and othersingular terms are intended to include the plural forms thereof unlessspecifically excluded. In addition, the term “set of” means one or more.

The description of data aggregation for drilling operations has beenpresented for purposes of illustration and description, and is notintended to be exhaustive or limited to data aggregation for drillingoperations in the form disclosed. Many modifications and variations willbe apparent to those of ordinary skill in the art. The embodiment waschosen and described in order to best explain the principles of dataaggregation for drilling operations, the practical application, and toenable others of ordinary skill in the art to understand dataaggregation for drilling operations for various embodiments with variousmodifications as are suited to the particular use contemplated.

1. A method for aggregating data for a drilling operation comprising:acquiring the data from a plurality of data sources associated with thedrilling operation; synchronizing a timing of the data for aggregatingthe data to generate synchronized aggregated data; determining adrilling context based on the synchronized aggregated data; assigningthe determined drilling context to the synchronized aggregated data;analyzing the synchronized aggregated data in the drilling context togenerate an analysis; and presenting the analysis to at least one user.2. The method of claim 1, and further comprising: adjusting the drillingoperation based on the analysis and an input of the at least one user.3. The method of claim 2, wherein the at least one user comprises aplurality of users at a plurality of different locations, and whereinadjusting the drilling operation based on the analysis and an input ofthe at least one user comprises adjusting the drilling operation basedon the analysis and inputs of each of the plurality of users.
 4. Themethod of claim 1, wherein the data comprises real-time data, andwherein synchronizing the timing of the data for aggregating the data togenerate the synchronized aggregated data comprises: identifying timesthat the real-time data is created at each of the plurality of datasources; and synchronizing the timing of the real-time data by adjustingthe times of the real-time data from each of the plurality of datasources to refer to a same clock.
 5. The method of claim 4, wherein thesame clock comprises a clock at a server that receives the real-timedata, and wherein identifying the timing that the real-time data iscreated at each of the plurality of data sources, comprises:synchronizing a clock at each of the plurality of data sources with theclock at the server.
 6. The method of claim 4, wherein identifying timesthat the real-time data is created at each of the plurality of datasources, further comprises: determining a round-trip latency of thereal-time data to be transmitted from a data source of the plurality ofdata sources to the server; and identifying the times that the real-timedata is created based on a time of receipt of the real-time data at theserver as adjusted by the round-trip latency.
 7. The method of claim 6,wherein determining the round-trip latency of the real-time data to betransmitted from the data source of the plurality of data sources to theserver, comprises: passing a token between the data source and theserver.
 8. The method of claim 1, wherein the acquired data comprisesreal-time data, and wherein synchronizing the timing of the data foraggregating the data to generate the synchronized aggregated datacomprises synchronizing the real-time data based on a correlatedsignature of data.
 9. The method of claim 1, wherein the acquired datacomprises video data and sound data associated with the drillingoperation.
 10. The method of claim 4, and after adjusting the times ofthe real-time data, further comprising performing a binning processbased on one selected from a group consisting of a minimal binning sizedetermined by a data channel having a highest data rate, a fixed binningsize determined by an application that consumes the data, and a variablebinning size determined by a time interval between two acquired datapoints.
 11. The method of claim 1, wherein determining a drillingcontext comprises: computing separate probabilities of drilling rigstates from the synchronized aggregated data; combining the separateprobabilities to provide a probability of the drilling rig being in oneof a plurality of probability states; and using a largest probabilitystate of the plurality of probability states to give the drillingcontext to subsequent acquired data.
 12. A system for aggregating datafor a drilling operation, the system comprising: a wellsite acquisitionand control mechanism for: aggregating the data acquired from aplurality of data sources to generate aggregated data, assigning adrilling context to the aggregated data, and adjusting the drillingoperation based on a control command; at least one server for storingthe aggregated data; and at least one monitoring mechanism for:receiving the aggregated data from the server, analyzing the aggregateddata in the drilling context to generate an analysis, and issuing thecontrol command based on the analysis.
 13. The system of claim 12,wherein the wellsite acquisition and control mechanism comprises asynchronization mechanism for synchronizing a timing of the acquireddata, wherein the synchronizing mechanism comprises: a clock at theserver; and an adjusting mechanism for adjusting a timing of theacquired data from each of the plurality of data sources to refer to theclock at the server.
 14. The system of claim 12, wherein the at leastone server comprises: a wellsite server located at the wellsite; and aremote server located at a remote location, wherein the aggregated datais periodically synchronized on the wellsite server and the remoteserver.
 15. The system of claim 12, wherein the at least one monitoringmechanism comprises a plurality of monitoring mechanisms at a pluralityof different locations, and wherein each of the plurality of monitoringmechanisms further comprises a presenting mechanism for presenting theanalysis to a user at each of the plurality of different locations. 16.The system of claim 15, wherein the presenting mechanism furthercomprises an alarm mechanism for presenting at least one alarm withrespect to at least one event with respect to the drilling operation tothe user.
 17. A computer readable medium, embodying instructionsexecutable by a computer to perform a method for aggregating data for adrilling operation, the instructions comprising functionality for:acquiring the data from a plurality of data sources associated with thedrilling operation; determining a round-trip latency of the acquireddata for each of the plurality of data sources; synchronizing a timingof the data based on at least the round-trip latency of each of theplurality of data sources to generate synchronized data; aggregating thesynchronized data based on the timing to generate synchronizedaggregated data; determining a drilling context based on thesynchronized aggregated data; and assigning the determined drillingcontext to the synchronized aggregated data.
 18. The computer readablemedium of claim 17, the instructions further comprising functionalityfor: analyzing the synchronized aggregated data in the drilling contextto generate an analysis; presenting the analysis to a plurality of usersat a plurality of different locations; and adjusting the drillingoperation based on the analysis and an input of at least one of theplurality of users.
 19. The computer readable medium of claim 17,wherein synchronizing a timing of the data to generate synchronized datacomprises: identifying times that the acquired data is created at eachof the plurality of data sources; and synchronizing the timing byadjusting the times of the acquired data from each of the plurality ofdata sources to refer to a clock at a server that receives the data. 20.The computer readable medium of claim 19, wherein determining around-trip latency of the acquired data for each of the plurality ofdata sources, comprises: passing a token between each of the pluralityof data sources and the server.